WEC ENERGY GROUP INC

Previous wording

We have already retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle power plant, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater 4 generating unit. We expect to retire approximately 1,200 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirement of OCPP Units 7 and 8 in late 2025, the planned retirement of the jointly-owned Columbia Units 1 and 2 by June 2026, and the planned retirement of Weston Unit 3 in 2031. For more information on the retirement of OCPP Units 5 and 6, see Note 6, Regulatory Assets and Liabilities. See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements.

Current wording

We have already retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle power plant, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater 4 generating unit. We expect to retire approximately 1,200 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirement of OCPP Units 7 and 8, the planned retirement of the jointly-owned Columbia Units 1 and 2, and the planned retirement of Weston Unit 3. For more information on the retirement of OCPP Units 5 and 6, see Note 6, Regulatory Assets and Liabilities. See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements.

Previous wording

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $7.0 billion from 2024-2028 in regulated renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments:

Current wording

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $9.1 billion from 2025-2029 in regulated renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments:

Previous wording

•2,700 MWs of utility-scale solar;

Current wording

•2,900 MWs of utility-scale solar;

Previous wording

We also plan on investing in a combination of clean, natural gas-fired generation, to be owned by WE, including:

Current wording

We also plan on investing in a combination of natural gas-fired generation, to be owned by WE, including:

Previous wording

•1,100 MWs of combustion turbines to be constructed at our OCPP site (we plan on constructing a new natural gas lateral pipeline to support this generation); and

Current wording

•1,100 MWs of combustion turbines to be constructed at our OCPP site (we plan on constructing a new natural gas lateral pipeline to support this generation); with

Previous wording

•128 MWs of RICE natural gas-fueled generation to be constructed in Kenosha County.

Current wording

•128 MWs of RICE natural gas-fueled generation to be constructed in Kenosha County; with

Previous wording

We also continue to reduce methane emissions by improving our natural gas distribution system. We set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our natural gas utility systems. In 2022, we received approval from the PSCW for our RNG pilots and in 2023, we began transporting the output of local dairy farms onto our natural gas distribution systems in Wisconsin. The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes. We currently have contracts in place for 1.9 Bcf of RNG.

Current wording

We also continue to reduce methane emissions by improving our natural gas distribution system. We set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our natural gas utility systems. In 2022, we received approval from the PSCW for our RNG pilots and in 2023, we began transporting the output of local dairy farms onto our natural gas distribution systems in Wisconsin. The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes. We currently have contracts in place for 1.9 Bcf of RNG. In addition, subject to regulatory approval, we may procure RTCs.

Previous wording

In December 2023, we started a pilot program with Electric Power Research Institute and CMBlu Energy, a Germany-based designer and manufacturer of an organic solid flow battery, to test this new form of long-duration energy storage on the U.S. electric grid at our Valley power plant. The program will test battery system performance, including the ability to store and discharge energy for up to twice as long as the typical lithium-ion batteries in use today. We expect the full pilot to be completed in 2024.

Current wording

In December 2023, we started a pilot program with Electric Power Research Institute and CMBlu Energy, a Germany-based designer and manufacturer of an organic solid flow battery, to test this new form of long-duration energy storage on the U.S. electric grid at our Valley power plant. The program will test battery system performance, including the ability to store and discharge energy for up to twice as long as the typical lithium-ion batteries in use today. We expect the pilot activities to continue into 2025.

Previous wording

•In April 2024, WE filed a request with the PSCW to construct an LNG facility with a storage capacity of two Bcf, which would be located on the OCPP site. In addition, the construction of additional LNG facilities in Wisconsin has been proposed as part of the 2024-2028 capital plan and would provide another approximately two Bcf of natural gas supply. The LNG facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.

Current wording

•In April 2024, WE filed a request with the PSCW to construct an LNG facility with a storage capacity of two Bcf, which would be located on the OCPP site. In addition, the construction of additional LNG facilities in Wisconsin has been proposed as part of the 2025-2029 capital plan and would provide another approximately four Bcf of natural gas supply. The LNG facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.

Previous wording

We expect to spend approximately $3.8 billion from 2024 to 2028 on reliability related projects with continued investment over the next decade. For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Current wording

We expect to spend approximately $4.5 billion from 2025 to 2029 on reliability related projects with continued investment over the next decade. For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Previous wording

Our planned investment focus from 2024 to 2028 is in our regulated utilities and non-utility energy infrastructure business, as well as our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $19.5 billion from 2024 to 2028. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $3 billion. We expect to invest approximately $1.2 billion in our non-utility energy infrastructure business over the same period, which includes our signed agreements to acquire the Delilah I and Maple Flats solar generating facilities. Specific projects included in the $23.7 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects. Also, see Note 2, Acquisitions, for information on recent and pending transactions.

Current wording

Our planned investment focus from 2025 to 2029 is in our regulated utilities and our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $24.4 billion from 2025 to 2029. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $3.2 billion. Over the same period, we expect to invest approximately $0.4 billion in our non-utility energy infrastructure business on the acquisition of Hardin III. Specific projects included in the $28.0 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects. Also, see Note 2, Acquisitions, for information on the acquisition of Hardin III and other recent and pending transactions.

Previous wording

The following table compares our consolidated results for the second quarter of 2024 with the second quarter of 2023, including favorable or better, "B", and unfavorable or worse, "W", variances:

Current wording

The following table compares our consolidated results for the third quarter of 2024 with the third quarter of 2023, including favorable or better, "B", and unfavorable or worse, "W", variances:

Previous wording

•A $27.1 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by a negative impact from an increase in an interim income tax expense and higher interest expense.

Current wording

•A $19.2 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by a negative impact from an increase in an interim income tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate. Higher interest expense also contributed to the increase in the net loss.

Previous wording

•A $13.2 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs from our non-utility renewable generating facilities in 2024, a positive impact from We Power due to continued capital investment, and higher operating income at WECI.

Current wording

These decreases in earnings were partially offset by a $17.6 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs from our non-utility renewable generating facilities and a positive impact from We Power due to continued capital investment.

Previous wording

The discussions below address the contribution of each of our segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margins (electric revenues less fuel and purchased power costs) and natural gas margins (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

Current wording

The discussions below address the contribution of each of our utility segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as utility margin, which is not a measure of financial performance under GAAP. Utility margin (operating revenues less fuel and purchased power costs and cost of natural gas sold) is a non-GAAP financial measure because it excludes certain operation and maintenance expenses applicable to revenues, as well as depreciation and amortization and property and revenue taxes.

Previous wording

We believe that electric and natural gas margins provide a useful basis for evaluating utility operations since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Current wording

We believe that utility margin provides a useful basis for evaluating utility operations since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses utility margin internally when assessing the operating performance of our utility segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of utility margin herein is intended to provide supplemental information for investors regarding our operating performance.

Previous wording

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. The following table shows operating income by segment for our utility operations during the second quarter of 2024 and 2023:

Current wording

Our utility margin may not be comparable to similar measures presented by other companies. Furthermore, this measure is not intended to replace gross margin as determined in accordance with GAAP as an indicator of operating performance. Each of our three utility segment discussions below include a table that provides the calculation of both gross margin as determined in accordance with GAAP and utility margin, as well as a reconciliation between the two measures.

Previous wording

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the second quarter of 2024 and 2023, $140.0 million and $127.9 million, respectively, of costs were billed to our electric utilities by transmission providers.

Current wording

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the third quarter of 2024 and 2023, $147.5 million and $136.4 million, respectively, of costs were billed to our electric utilities by transmission providers.

Previous wording

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the second quarter of 2024 and 2023, $29.3 million and $35.8 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

Current wording

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the third quarter of 2024 and 2023, $27.8 million and $26.7 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

Previous wording

This decrease in margins was partially offset by a $3.6 million increase in margins related to higher retail sales volumes, driven by the impact of warmer spring weather in WE's service area during the second quarter of 2024, compared with the same quarter in 2023. As measured by cooling degree days, the second quarter of 2024 was 27.8% warmer than the same quarter in 2023 in the Milwaukee area.

Current wording

•A $12.4 million increase in margins related to higher electric and natural gas retail sales volumes, including the impact of warmer summer weather in WPS's service area during the third quarter of 2024, compared with the same quarter in 2023. As measured by cooling degree days, the third quarter of 2024 was 15.6% warmer than the same quarter in 2023 in the Green Bay area.

Previous wording

Electric utility margins at the Wisconsin segment decreased $4.6 million during the second quarter of 2024, compared with the same quarter in 2023. The significant factor impacting the lower electric utility margins was a $7.2 million quarter-over-quarter negative impact from collections of fuel and purchased power costs. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for either future recovery or refund to customers.

Current wording

•A $4.7 million quarter-over-quarter positive impact from collections of fuel and purchased power costs. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance above or below the 2% is generally deferred for either future recovery from or refund to customers.

Previous wording

Natural gas utility margins at the Wisconsin segment increased $0.2 million during the second quarter of 2024, compared with the same quarter in 2023. The most significant factor impacting the higher natural gas utility margins was a $7.2 million increase in margins related to the impact of the Wisconsin limited rate case re-openers approved by the PSCW, effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K, for more information on the 2024 limited rate case re-openers. This increase in margins was partially offset by a $6.3 million decrease in margins from lower retail sales volumes, driven by the impact of warmer spring weather during the second quarter of 2024, compared with the same quarter in 2023. As measured by heating degree days, the second quarter of 2024 was 16.8% and 12.9% warmer than the same quarter in 2023 in the Milwaukee area and Green Bay area, respectively.

Current wording

•A $2.2 million increase in margins driven by the impact of the Wisconsin limited rate case re-openers approved by the PSCW, effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K, for more information on the 2024 limited rate case re-openers.

Previous wording

•A $3.3 million increase related to MERC's final rate increase approved by the MPUC in November 2023.

Current wording

•A $3.3 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

Previous wording

Interest expense at the Wisconsin segment increased $7.2 million during the second quarter of 2024, compared with the same quarter in 2023, driven by higher average short-term debt balances, increased short-term debt interest rates, and the impact of WE's $350.0 million long-term debt issuance in May 2024.

Current wording

Interest expense at the Wisconsin segment increased $11.6 million during the third quarter of 2024, compared with the same quarter in 2023, driven by the impact of WE's $350.0 million long-term debt issuance in May 2024 and $600.0 million long-term debt issuance in September 2024. See Note 11, Long-Term Debt, for more information. Also contributing to the increase was higher average short-term debt balances and increased average short-term debt interest rates.

Previous wording

The Illinois segment's contribution to net income attributed to common shareholders was $25.7 million during the second quarter of 2024, representing a $4.4 million, or 14.6%, decrease over the same quarter in 2023. The lower earnings were driven by a decrease in natural gas utility margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are lower during the second quarter when natural gas usage is lower, this rate design change drove a decrease in second quarter 2024 margins.

Current wording

The Illinois segment's net loss attributed to common shareholders was $48.6 million during the third quarter of 2024, representing a $73.3 million decrease in earnings over the same quarter in 2023. The lower earnings were driven by a decrease in margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are lower during the third quarter when natural gas usage is lower, this rate design change drove a decrease in third quarter 2024 earnings. See Note 25, Regulatory Environment, for more information on the rate orders. Higher operating expenses and a $25.3 million pre-tax charge to income related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation also contributed to the lower earnings. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information on the ICC disallowance.

Previous wording

•A $70.0 million increase in net income attributed to common shareholders at the Illinois segment, driven by an increase in natural gas margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are concentrated in the winter months (first and fourth quarters) when natural gas usage is highest, this rate design change drove a large increase in the first quarter 2024 margins. See Note 25, Regulatory Environment, for more information on the rate orders.

Current wording

•A $47.6 million decrease in margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. PGL’s rate order includes the recovery of costs related to PGL’s SMP in base rates. Previously, these costs were being recovered under its QIP rider. As base revenues are lower during the third quarter when natural gas usage is lower, this rate design change drove a decrease in third quarter 2024 margins. See Note 25, Regulatory Environment, for more information on the rate orders.

Previous wording

Other operating expenses at the Illinois segment decreased $3.2 million, net of the $9.1 million impact of the riders referenced in the table above, during the second quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the decrease in other operating expenses were:

Current wording

Other operating expenses at the Illinois segment increased $37.6 million, net of the $12.5 million impact of the riders referenced in the table above, during the third quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other operating expenses were:

Previous wording

•A $3.4 million increase in property and revenue taxes, driven by an increase in the invested capital tax. This increase was related to an increase in regulatory amortizations as approved in the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively.

Current wording

•A $5.5 million increase in property and revenue taxes, driven by an increase in the invested capital tax. This increase was related to an increase in regulatory amortizations as approved in the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively.

Previous wording

•A $4.7 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.

Current wording

•A $3.1 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.

Previous wording

•A $2.0 million increase in customer service expense primarily due to higher metering costs.

Current wording

•A $3.0 million increase in customer service expense primarily due to higher metering costs.

Previous wording

Interest expense at the Illinois segment increased $2.1 million during the second quarter of 2024, compared with the same quarter in 2023, due primarily to the impact of PGL and NSG issuing long-term debt in November 2023.

Current wording

Interest expense at the Illinois segment increased $0.3 million during the third quarter of 2024, compared with the same quarter in 2023, due primarily to the impact of PGL and NSG issuing long-term debt in November 2023. This increase was partially offset by lower average short-term debt balances.

Previous wording

•A $2.8 million increase in margins related to higher sales volumes, including steam operations, driven by the impact of warmer spring weather in WE's service area during the six months ended June 30, 2024, compared with the same period in 2023. As measured by cooling degree days, the six months ended June 30, 2024 were 27.8% warmer than the same period in 2023 in the Milwaukee area.

Current wording

•A $3.1 million increase related to higher sales volumes, driven by higher retail sales.

Previous wording

These increases in other operating expenses were partially offset by:

Current wording

Partially offsetting these increases in margins was a $1.8 million decrease related to the timing of MERC's interim rates and final rates, which were approved by the MPUC in November 2023. See Note 25, Regulatory Environment, for more information.

Previous wording

Income tax expense at the Illinois segment decreased $0.7 million during the second quarter of 2024, compared with the same quarter in 2023, driven by a decrease in pre-tax income.

Current wording

The income tax benefit at the other states segment decreased $0.7 million during the third quarter of 2024, compared with the same quarter in 2023, driven by lower pre-tax loss.

Previous wording

Equity in earnings of transmission affiliates increased $3.2 million during the second quarter of 2024, compared with the same quarter in 2023. This increase was primarily due to continued capital investment by ATC.

Current wording

Equity in earnings of transmission affiliates increased $2.0 million during the third quarter of 2024, compared with the same quarter in 2023. This increase was primarily due to continued capital investment by ATC.

Previous wording

•A $15.2 million positive impact in 2024 related to the receipt of performance payments.

Current wording

•A $9.2 million positive impact in 2024 related to the receipt of performance payments.

Previous wording

•A $3.7 million increase in PPA revenue resulting from increased generation driven by higher wind speeds.

Current wording

•A $1.8 million increase in PPA revenue resulting from increased generation driven by higher wind speeds.

Previous wording

•A $3.7 million decrease in margin related to transmission congestion that reduced energy market prices.

Current wording

•A $5.3 million decrease in revenue related to transmission congestion that reduced energy market prices.

Previous wording

•A $7.8 million increase in operation and maintenance expenses due primarily to equipment failures at several of our renewable generation facilities.

Current wording

•A $3.3 million increase in operation and maintenance expenses due primarily to equipment failures at several of our renewable generation facilities.

Previous wording

•Recognition of $4.5 million in revenue related to Blooming Grove in 2023 for a capacity payment received from PJM Interconnection that was associated with a December 2022 cold weather event. The capacity payment was subject to a FERC complaint, so we recognized this as revenue in 2023 when FERC issued an order denying that complaint.

Current wording

•Recognition of $1.9 million in revenue related to Blooming Grove in 2023 for a capacity payment received from PJM Interconnection that was associated with a December 2022 cold weather event. The capacity payment was subject to a FERC complaint, so we recognized this as revenue in 2023 when FERC issued an order denying that complaint.